This disclosure relates to the examination of porous samples, which may be porous rock, using nuclear magnetic resonance (NMR). In some embodiments of this invention the samples may be material collected in the course of drilling into subterranean rock formations.
It is conventional practice when drilling through underground rock to drill around a central cylinder of rock which is subsequently detached and brought to the surface as a sample, habitually referred to as a rock core. Once brought to the surface, rock cores or pieces cut from them may be subjected to various measurements and tests. The collection of such samples and their examination may be done in connection with exploration for, or exploitation of, hydrocarbons in underground reservoirs. It is also possible that it may be done in connection with exploration for, or the utilisation or management of, underground water, or in connection with schemes for the storage of captured carbon dioxide.
These tests may relate to the pore space of the sample and liquid therein. One characteristic which may be examined is capillary pressure and it can be desirable to determine a capillary pressure curve for the rock sample. Capillary pressure arises when there is an interface between two immiscible fluids in the pores of porous rock. Commonly both fluids are liquids with one wetting the rock and the other being a non-wetting phase, although it is also possible that one fluid is a gas. Capillary pressure arises because the pores, and more specifically the pore throats, act as capillaries. A pore throat is the narrowest point in the pathway into a pore. This capillary pressure can oppose the displacement of a wetting fluid by a non-wetting fluid and has a magnitude dependant on properties of the fluids and on pore throat size. Where there is a distribution of pore throat sizes there will be a distribution of capillary pressures, with the smallest pore throats giving the largest capillary pressure. A capillary pressure curve is a graph of the saturation of the pore space of the sample, usually expressed as a percentage of the total pore space, plotted against capillary pressure.
Determination of pore throat size distribution or the related parameter of a capillary pressure curve is one approach to characterizing rock properties. Another approach to the characterization of rock is the distribution of pore body size which can be obtained by measurement of the distribution of an NMR parameter: transverse relaxation time T2 
Pore throat size and pore body size are of course different although there has been some tendency to assume that a pore body size distribution correlates with the pore throat size distribution and then assume that a curve calculated from a pore body size distribution is an acceptable approximation to a capillary pressure curve.
A number of methods of measurement are commonly used examination of rock samples. Generally these obtain values or distributions of values which are an average for the whole sample under examination.
One well-established method of determining the sizes of pores in a rock is Mercury Injection Capillary Pressure (MICP) or Mercury Porosimetry. This core analysis measurement is widely used in reservoir engineering for Reservoir Rock Typing (RRT) i.e., classification of rocks in a petroleum-bearing formation. The injection of mercury into a dry, evacuated rock at various pressures is measured and the incremental injection volumes at various pressures are used to derive a Pore Size Distribution (PSD) for the rock, where the pore “size” is pore throat size derived from the Washburn equation for a capillary.
Another approach to measurement recognizes that a capillary pressure curve can be established for sample which contains, or is in contact with, two immiscible fluids. Such a curve can be established for a sample where a liquid is being replaced by a gas, usually air (drainage) or where a liquid is replacing gas (imbibition) or where one liquid is replacing another. A known test procedure for obtaining a capillary pressure curve entails centrifuging a liquid-saturated porous sample at various speeds. Liquid drains from pores in the sample when centripetal acceleration overcomes capillary pressure, which can therefore be determined by measuring the amount of liquid which drains from the sample at the various speeds, as originally described in Hassler, G. L., Brunner, E., “Measurement of Capillary Pressure in Small Core Samples”, Trans. AIME, 1945, 160, 114-123 also published as Society of Petroleum Engineers paper SPE 945114-G.
It is also known, for the purpose of obtaining a capillary pressure curve, to centrifuge a sample and then use nuclear magnetic resonance (NMR) sometimes termed magnetic resonance imaging (MRI) to measure a liquid saturation profile, i.e., measure the amount of liquid at a plurality of positions along the length of the rock sample.
This has been described in U.S. Pat. No. 4,868,500 for brine which is replaced by air as a centrifuge forces drainage of brine from the rock sample. In U.S. Pat. No. 6,178,807 it has been described for a combination of oil and brine where centrifuging causes one liquid to replace the other within the rock sample. See also Chen and Balcom in Journal of Chemical Physics Vol. 122, 214720 (2005) and the related U.S. Pat. No. 7,352,179.
The extent of pore saturation, i.e., the amount of the liquid in the pores, may be determined from the intensity of the magnetic resonance signal for each position along the length of the rock sample. The spatial position from which resonant nuclei emitted signals may be detected using coils to superimpose a magnetic field gradient onto the main magnetic field, so that the spatial position is “frequency encoded”.
The literature has also disclosed techniques in which the spatial position in a rock sample is indicated by the phase of the received signals, so that the spatial position is said to be “phase encoded.” An advantage of phase encoded imaging is that each data point is recorded at a fixed time after initial excitation, so any effects arising from relaxation after the initial excitation are the same for the entire sample.
A phase encoded single point imaging (SPI) pulse sequence disclosed by S. Emid and J. H. N. Creyghton, “High-resolution NMR imaging in solids,” Physica B & C, Vol. 128(1), pp. 81-83, 1985 may be used for the measurement of saturation profiles in reservoir rock samples. The SPI pulse sequence has been improved by use of small angle radio frequency spin excitation pulses (see B. J. Balcom et al., “Single-point ramped imaging with T1 enhancement (SPRITE),” J. Magn. Reson. Ser. A, Vol. 123(1), pp. 131-134, 1996).
Whilst there is a distinct difference between phase encoded and frequency encoded techniques, as pointed out above, it should also be appreciated that the literature describes a variety of frequency encoded techniques as well as a variety of phase encoded techniques.